Natural gas liquefaction core modules, plants including same and related methods

ABSTRACT

A method of natural gas liquefaction may include liquefying natural gas from a first natural gas source with a first core module, and liquefying natural gas from at least a second natural gas source having a gas property different than a gas property of the first natural gas source with at least a second core module substantially identical to the first core module. Additionally, a method of designing a natural gas liquefaction plant may include utilizing a preconfigured core module design for a core module configured to receive source gas at site-independent predetermined input conditions, expel tail gas at site-independent predetermined outlet conditions, and liquefy natural gas. Furthermore, a method of distributing liquid natural gas may include providing a plurality of natural gas liquefaction plants comprising substantially identical core modules to a plurality of gaseous natural gas source locations. Finally, a modular natural gas liquefaction plant may include a preconfigured core module, and site-specific inlet and outlet modules.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is related to U.S. patent application Ser. No.09/643,420, filed Aug. 23, 2001, for APPARATUS AND PROCESS FOR THEREFRIGERATION, LIQUEFACTION AND SEPARATION OF GASES WITH VARYING LEVELSOF PURITY, now U.S. Pat. No. 6,425,263, issued Jul. 30, 2002, which is acontinuation of U.S. patent application Ser. No. 09/212,490, filed Dec.16, 1998, for APPARATUS AND PROCESS FOR THE REFRIGERATION, LIQUEFACTIONAND SEPARATION OF GASES WITH VARYING LEVELS OF PURITY, now U.S. Pat. No.6,105,390, issued Aug. 22, 2000, which claims the benefit of U.S.Provisional Patent Application Ser. No. 60/069,698 filed Dec. 16, 1997.This application is also related to U.S. patent application Ser. No.11/381,904, filed May 5, 2006, for APPARATUS FOR THE LIQUEFACTION OFNATURAL GAS AND METHODS RELATING TO SAME; U.S. patent application Ser.No. 11/383,411, filed May 15, 2006, for APPARATUS FOR THE LIQUEFACTIONOF NATURAL GAS AND METHODS RELATING TO SAME; U.S. patent applicationSer. No. 11/560,682, filed Nov. 16, 2006, for APPARATUS FOR THELIQUEFACTION OF GAS AND METHODS RELATING TO SAME; U.S. patentapplication Ser. No. 11/536,477, filed Sep. 28, 2006, for APPARATUS FORTHE LIQUEFACTION OF A GAS AND METHODS RELATING TO SAME; U.S. patentapplication Ser. No. 11/674,984, filed Feb. 14, 2007, for SYSTEMS ANDMETHODS FOR DELIVERING HYDROGEN AND SEPARATION OF HYDROGEN FROM ACARRIER MEDIUM, which is a continuation-in-part of U.S. patentapplication Ser. No. 11/124,589, filed May 5, 2005, for APPARATUS FORTHE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME, now U.S.Pat. No. 7,219,512, issued May 22, 2007, which is a continuation of U.S.patent application Ser. No. 10/414,991, filed Apr. 14, 2003, forAPPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TOSAME, now U.S. Pat. No. 6,962,061, issued Nov. 8, 2005, and U.S. patentapplication Ser. No. 10/414,883, filed Apr. 14, 2003, for APPARATUS FORTHE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME, now U.S.Pat. No. 6,886,362, issued May 3, 2005, which is a divisional of U.S.patent application Ser. No. 10/086,066, filed Feb. 27, 2002, forAPPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATED TOSAME, now U.S. Pat. No. 6,581,409, issued Jun. 24, 2003, and whichclaims the benefit of U.S. Provisional Patent Application Ser. No.60/288,985, filed May 4, 2001, for SMALL SCALE NATURAL GAS LIQUEFACTIONPLANT. This application is also related to U.S. patent application Ser.No. 11/855,071, filed Sep. 13, 2007, for HEAT EXCHANGER AND ASSOCIATEDMETHODS; U.S. patent application Ser. No. ______, filed on even dateherewith, for COMPLETE LIQUEFACTION METHODS AND APPARATUS (AttorneyDocket No. 2939-9177US (BA-347)); and U.S. patent application Ser. No.______, filed on even date herewith, for METHODS OF NATURAL GASLIQUEFACTION AND NATURAL GAS LIQUEFACTION PLANTS UTILIZING MULTIPLE ANDVARYING GAS STREAMS (Attorney Docket No. 2939-9179US (BA-350)). Thedisclosure of each of the foregoing documents is hereby incorporated byreference in its entirety.

GOVERNMENT RIGHTS

This invention was made with government support under Contract NumberDE-AC07-05ID14517 awarded by the United States Department of Energy. Thegovernment has certain rights in the invention.

TECHNICAL FIELD

The present invention relates generally to the compression andliquefaction of gases and, more particularly, to the partialliquefaction of a gas, such as natural gas, by a modular natural gasliquefaction plant utilizing a core module.

BACKGROUND

Natural gas is a known alternative to combustion fuels such as gasolineand diesel. Much effort has gone into the development of natural gas asan alternative combustion fuel in order to combat various drawbacks ofgasoline and diesel including production costs and the subsequentemissions created by the use thereof. As is known in the art, naturalgas is a cleaner burning fuel than other combustion fuels. Additionally,natural gas is considered to be safer than gasoline or diesel as naturalgas will rise in the air and dissipate, rather than settling.

To be used as an alternative combustion fuel, natural gas (also termed“feed gas” herein) is conventionally converted into compressed naturalgas (CNG) or liquified (or liquid) natural gas (LNG) for purposes ofstoring and transporting the fuel prior to its use. Conventionally, twoof the known basic cycles for the liquefaction of natural gases arereferred to as the “cascade cycle” and the “expansion cycle.”

Briefly, the cascade cycle consists of a series of heat exchanges withthe feed gas, each exchange being at successively lower temperaturesuntil liquefaction is accomplished. The levels of refrigeration areobtained with different refrigerants or with the same refrigerant atdifferent evaporating pressures. The cascade cycle is considered to bevery efficient at producing LNG as operating costs are relatively low.However, the efficiency in operation is often seen to be offset by therelatively high investment costs associated with the expensive heatexchange and the compression equipment associated with the refrigerantsystem. Additionally, a liquefaction plant incorporating such a systemmay be impractical where physical space is limited, as the physicalcomponents used in cascading systems are relatively large.

In an expansion cycle, gas is conventionally compressed to a selectedpressure, cooled, and then allowed to expand through an expansionturbine, thereby producing work as well as reducing the temperature ofthe feed gas. The low temperature feed gas is then heat exchanged toeffect liquefaction of the feed gas. Conventionally, such a cycle hasbeen seen as being impracticable in the liquefaction of natural gassince there is no provision for handling some of the components presentin natural gas which freeze at the temperatures encountered in the heatexchangers, for example, water and carbon dioxide.

Additionally, to make the operation of conventional systems costeffective, such systems are conventionally built on a large scale tohandle large volumes of natural gas. As a result, fewer facilities arebuilt, making it more difficult to provide the raw gas to theliquefaction plant or facility as well as making distribution of theliquefied product an issue. Another major problem with large-scalefacilities is the capital and operating expenses associated therewith.For example, a conventional large-scale liquefaction plant, i.e.,producing on the order of 70,000 gallons of LNG per day, may cost $16.3million to $24.5 million, or more, in capital expenses.

An additional problem with large facilities is the cost associated withstoring large amounts of fuel in anticipation of future use and/ortransportation. Not only is there a cost associated with building largestorage facilities, but there is also an efficiency issue relatedtherewith as stored LNG will tend to warm and vaporize over timecreating a loss of the LNG fuel product. Further, safety may become anissue when larger amounts of LNG fuel product are stored.

In confronting the foregoing issues, various systems have been devisedwhich attempt to produce LNG or CNG from feed gas on a smaller scale, inan effort to eliminate long-term storage issues and to reduce thecapital and operating expenses associated with the liquefaction and/orcompression of natural gas.

For example, small scale LNG plants have been devised to produce LNG ata pressure letdown station, wherein gas from a relatively high pressuretransmission line is utilized to produce LNG and tail gases from theliquefaction process are directed into a single lower pressuredownstream transmission line. However, such plants may only be suitablefor pressure let down stations having a relatively high pressuredifference between upstream and downstream transmission lines, or may beinefficient at pressure let down stations having relatively low pressuredrops. In view of this, the production of LNG at certain existing letdown stations may be impractical using existing LNG plants. Furthermore,the costs to design, engineer, and manufacture LNG plants for a varietyof natural gas source locations, which may each supply NG at differentgas conditions, such as at various temperatures and pressures, may makeit impractical to build an LNG plant for smaller markets.

Additionally, since many sources of natural gas, such as residential orindustrial service gas, are considered to be relatively “dirty,” therequirement of providing “clean” or “pre-purified” gas is actually arequirement of implementing expensive and often complex filtration andpurification systems prior to the liquefaction process. This requirementsimply adds expense and complexity to the construction and operation ofsuch liquefaction plants or facilities.

In view of the shortcomings in the art, it would be advantageous toprovide a process, and a plant for carrying out such a process, ofefficiently producing liquefied natural gas, such as on a small scale.More particularly, it would be advantageous to provide a system forproducing liquefied natural gas from a source of relatively “dirty” or“unpurified” natural gas at various levels of inlet pressure and inlettemperature and the return of natural gas from the plant. Such a systemor process may include various clean-up cycles which are integrated withthe liquefaction cycle for purposes of efficiency. Further, it would beadvantageous for the process and plant to be readily transportable usingavailable sources of transportation over public roads and highways toother geographic locations. It would be advantageous for the process andplant be capable of being operated in a variety of geographicallocations without substantially changing the process and apparatus ofthe plant.

It would be additionally advantageous to provide a plant for theliquefaction of natural gas which is relatively inexpensive to build andoperate, and which desirably requires little or no operator oversight.

It would be advantageous to provide a plant for the liquefaction ofnatural gas which having a core module of substantially standardizedcomponents operably coupled in a substantially standardized manner andsuitable for use in a wide variety of site conditions with minimal or nointernal modification being required of the core module.

It would be additionally advantageous to provide such a plant which iseasily transportable and which may be located and operated at existingsources of natural gas which are within or near populated communities,thus providing easy access for consumers of LNG fuel.

BRIEF SUMMARY

In some embodiments, a method of natural gas liquefaction may includeliquefying natural gas from a first natural gas source with a first coremodule, and liquefying natural gas from at least a second natural gassource having a gas property different than a gas property of the firstnatural gas source with at least a second core module substantiallyidentical to the first core module.

In additional embodiments, a method of designing a natural gasliquefaction plant may include utilizing a preconfigured core moduledesign for a core module configured to receive source gas atsite-independent predetermined input conditions, expel tail gas atsite-independent predetermined outlet conditions, and liquefy naturalgas. The method may further include designing a site-specific inletmodule configured to provide source gas from a specific natural gassource to the core module at the fixed predetermined input conditions,and designing a site-specific outlet module configured to convey tailgas from the core module at the predetermined tail gas outlet conditionsto a specific tail gas stream.

In further embodiments, a method of distributing liquid natural gas mayinclude providing a plurality of substantially identical core modules toa plurality of gaseous natural gas source locations. The method mayfurther include liquefying at least a portion of the gaseous natural gasfrom each of the plurality of gaseous natural gas sources with theplurality of substantially identical core modules to provide liquidnatural gas at each of the plurality of gaseous natural gas sourcelocations.

In additional embodiments, methods of natural gas liquefaction maycomprise liquefying gaseous natural gas with a plurality ofsubstantially identical core modules at a single site.

In yet further embodiments, a modular natural gas liquefaction plant mayinclude a core module, an inlet module and an outlet module. The coremodule may include a processed natural gas inlet configured to receivegaseous natural gas at a site-independent predetermined pressure andtemperature, a liquid natural gas outlet, and a tail gas outletconfigured to expel a tail gas at a site-independent predeterminedpressure and temperature. The inlet module may include a natural gassource inlet configured to receive gaseous natural gas at a temperatureand pressure of a site-specific natural gas source; and a processednatural gas outlet configured to deliver gaseous natural gas to theprocessed natural gas inlet of the core module at the site-independentpredetermined pressure and temperature. Finally, the outlet module mayinclude a tail gas inlet configured to receive a tail gas from the tailgas outlet of the core module at the site-independent predeterminedpressure and temperature; and a processed tail gas outlet configured todeliver the tail gas to a site-specific location at a site-specificpressure and temperature.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

The foregoing and other advantages of the invention will become apparentupon reading the following detailed description and upon reference tothe drawings.

FIG. 1 is a schematic overview of a core module for a liquefaction plantaccording to an embodiment of the present invention.

FIG. 2 is a flow diagram depicting a site having a gas supply pipelineand a tail gas pipeline for a modular type liquefaction plant accordingto embodiments of the present invention.

FIG. 3 is a flow diagram depicting another site having a single gassupply pipeline that may be utilized to supply gas to and receive tailgas from a modular type liquefaction plant according to embodiments ofthe present invention.

DETAILED DESCRIPTION

A modular type liquefaction plant having a core module designed so thatit may be used for a variety of site conditions, may be readilytransported to site locations, and may be readily manufactured usingcommon, substantially standardized components therein so as to becapable of use at a wide variety of site locations and conditionssubstantially without modification.

Illustrated in FIG. 1 is a schematic overview of a core module 2 fornatural gas (NG) liquefaction according to an embodiment of the presentinvention. The core module 2 may include a primary gas inlet 4 coupledto a splitter 6, and a primary gas outlet 8 coupled to a mixer 10. Aprocess stream 12, a cooling stream 14, and a transfer motive gas stream16 may originate from the splitter 6 of the primary gas inlet 4 and thecooing stream 14, as well as tail streams 26, 30, may be combined in themixer 10 and directed out of the core module 2 through the primary gasoutlet 8.

As shown in FIG. 1, the process stream 12 may be directed through a NGinlet 32 from the splitter 6, and then directed through a primary heatexchanger 34 and an expansion valve 36. The process stream 12 may thenbe directed though a gas-liquid separation tank 38, a transfer tank 40,a hydrocyclone 42 and a filter 44. Finally, the process stream 12 may bedirected through a splitter 46, a valve 48, a storage tank 50 and aliquid natural gas (LNG) outlet 52.

As further shown in FIG. 1, the cooling stream 14 may be directedthrough a cooling fluid inlet 54 from the splitter 6, and then directedthrough a turbo compressor 56, an ambient heat exchanger 58, the primaryheat exchanger 34, a turbo expander 60, and finally, through a coolingfluid outlet 62 and into the mixer 10. Additionally, the transfer motivegas stream 16 may be directed through a transfer fluid inlet 64 from thesplitter 6, and then through an expansion valve 66 to the transfer tank40. In additional embodiments, the transfer motive gas stream 16 mayoriginate from other suitable locations of the core module 2.Optionally, the transfer motive gas stream 16 may also be directedthrough the primary heat exchanger 34.

A first tail gas stream 30 may include a combination of streams from thecore module 2. For example, as shown in FIG. 1, the first tail gasstream 30 may include a carbon dioxide management stream 22, aseparation chamber vent stream 18, a transfer tank vent stream 20, and astorage tank vent stream 24. The carbon dioxide management stream 22 maybe directed from an underflow outlet 82 of the hydrocyclone 42, and thenmay be directed through a sublimation chamber 70, the primary heatexchanger 34 and finally through a first tail gas outlet 72 into themixer 10. Additionally, the separation chamber vent stream 18 may bedirected from a gas outlet of the gas liquid separation tank 38, thetransfer tank vent stream 20 may be directed from the transfer tank 40,and a storage tank vent stream 24 may be directed from the storage tank50. The separation chamber vent stream 18, the transfer tank vent stream20, and the storage tank vent stream 24 may then be directed through amixer 74, the heat exchanger 34, a compressor 76, and into thesublimation chamber 70 to be mixed with the carbon dioxide managementstream 22 to form the first tail gas stream 30.

Finally, as shown in FIG. 1, a second tail gas stream 26 may be directedfrom an outlet of the splitter 46. The second tail gas stream 26 maythen be directed through a pump 78, the heat exchanger 34, and finally,through a second tail gas outlet 80 into the mixer 10. In additionalembodiments, the pump 78 may not be required and may not be included inthe plant 10. For example, sufficient pressure may be imparted to theprocess stream 12 within the transfer tank 40 by the transfer motive gasstream 16 such that the pump 78 may not be required and may not beincluded in the core module 2.

In operation, a gaseous NG may be provided to the core module 2 throughthe primary gas inlet 4, which may be divided by the splitter 6 into thecooling stream 14, the process stream 12, and the transfer motive stream16. The cooling stream 14 may be directed from the splitter 6 throughthe cooling fluid inlet 54 and then directed into the turbo compressor56 to be compressed. The compressed cooling stream 14 may then exit theturbo compressor 56 and be directed into the ambient heat exchanger 58,which may transfer heat from the cooling stream 14 to ambient air.Additionally, the cooling stream 14 may be directed through a firstchannel of the primary heat exchanger 34, where it may be furthercooled.

In some embodiments, the primary heat exchanger 34 may comprise a highperformance aluminum multi-pass plate and fin type heat exchanger, suchas may be purchased from Chart Industries Inc., 1 Infinity CorporateCentre Drive, Suite 300, Garfield, Heights, Ohio 44125, or other wellknown manufacturers of such equipment.

After passing through the primary heat exchanger 34, the cooling stream14 may be expanded and cooled in the turbo expander 60. For example, theturbo expander 60 may comprise a turbo expander having a specific designfor a mass flow rate, pressure level of gas, and temperature of gas tothe inlet, such as may be purchased from GE Oil and Gas, 1333 West LoopSouth, Houston, Tex. 77027-9116, USA, or other well known manufacturersof such equipment. Additionally, the energy required to drive the turbocompressor 56 may be provided by the turbo expander 60, such as by theturbo expander 60 being directly connected to the turbo compressor 56 orby the turbo expander 60 driving an electrical generator (not shown) toproduce electrical energy to drive an electrical motor (not shown) thatmay be connected to the turbo compressor 56. The cooled cooling stream14 may then be directed through a second channel of the primary heatexchanger 34 and then through the cooling fluid outlet 62 into the mixer10 to be directed out of the core module 2 through the primary gasoutlet 8.

Meanwhile, a gaseous NG stream may be directed from the splitter 6 intothe NG inlet 32 to provide the process stream 12 to the core module 2and the process stream 12 may then be directed through a third channelof the primary heat exchanger 34. Heat from the process stream 12 may betransferred to the cooling stream 14 within the primary heat exchanger34 and the process stream 12 may exit the primary heat exchanger 34 in acooled gaseous state. The process stream 12 may then be directed throughthe expansion valve 36, such as a Joule-Thomson expansion valve, whereinthe process stream 12 may be expanded and cooled to form a liquidnatural gas (LNG) portion and a gaseous NG portion. Additionally, carbondioxide (CO₂) that may be contained within the process stream 12 maybecome solidified and suspended within the LNG portion, as carbondioxide has a higher freezing temperature than methane (CH₄), which isthe primary component of NG. The LNG portion and the gaseous portion maybe directed into the gas-liquid separation tank 38, and the LNG portionmay be directed out of the separation tank 38 as a LNG process stream12, which may then be directed into the transfer tank 40. A transfermotive gas stream 16 may then be directed through the transfer motivegas inlet 64 from the splitter 6 through the valve 66, which may beutilized to regulate the pressure of the transfer motive gas stream 16prior to being directed into the transfer tank 40. The transfer motivegas stream 16 may facilitate the transfer of the liquid NG processstream 12 through the hydrocyclone 42, such as may be available, forexample, from Krebs Engineering of Tucson, Ariz., wherein the solid CO₂may be separated from the liquid NG process stream 12.

Optionally, a separate transfer tank 40 may not be used and instead aportion of the separation tank 38 may be utilized as a transfer tank totransfer the process stream 12 into the hydrocyclone 42. In additionalembodiments, a pump may be utilized to transfer the process stream fromthe separation tank 38 into the hydrocyclone. A pump may provide certainadvantages, as it may provide a constant system flow, when compared to abatch process utilizing a transfer tank. However, a transfer tankconfiguration, such as shown in FIG. 1, may provide a more reliableprocess stream 12 flow. In yet further embodiments, a plurality oftransfer tanks 40 may be utilized; optionally, a plurality ofhydrocyclones 42 may also be utilized. Such a configuration may improveflow regularity of the process stream 12 through the core module 2 whilemaintaining a reliable flow of the process stream 12. Additionally, anaccumulator (not shown) may be provided and the transfer motive gasstream 16 may be accumulated in the accumulator prior to being directedinto the transfer tank 40 to facilitate an expedient transfer of theprocess stream 12 out of the transfer tank 40 and through thehydrocyclone 42.

In the hydrocyclone 42, a slurry including the solid CO₂ from the LNGprocess stream 12 may be directed through an underflow outlet 82 and theLNG process stream 12 may be directed through an overflow outlet 84. TheLNG process stream 12 may then be directed through the filter 44, whichmay remove any remaining CO₂ or other impurities, which may be removedfrom the system through a filter outlet 86, such as during a cleaningprocess. In some embodiments, the filter 44 may comprise one screenfilter or a plurality of screen filters that are placed in parallel. Asubstantially pure LNG process stream 12, such as substantially pureliquid CH4, may then exit the filter 44 and be directed into a LNGprocess stream 12 and a secondary LNG stream that may form the secondtail stream 26. The LNG process stream 12 may be directed through thevalve 48 and into the storage tank 50, wherein it may be withdrawn foruse through the LNG outlet 52, such as to a vehicle which is powered byLNG or into a transport vehicle.

Additionally, the CO₂ slurry in the hydrocyclone 42 may be directedthrough the underflow outlet 82 to form the CO₂ management stream 22 andbe directed to the CO₂ sublimation chamber 70 to sublimate the solid CO₂for removal from the core module 2. Additionally, the separation chambervent stream 18, the transfer tank vent stream 20 and the storage tankvent stream 24 may be combined in the mixer 74 to provide a gas stream28 that may be used to sublimate the CO₂ management stream 22. The gasstream 28 may be relatively cool upon exiting the mixer 74 and may bedirected through a fourth channel of the primary heat exchanger 34 toextract heat from the process stream 12 in the third channel of theprimary heat exchanger 34. The gas stream 28 may then be directedthrough the compressor 76 to further pressurize and warm the gas stream28 prior to directing the gas stream 28 into the CO₂ sublimation chamber70 to sublimate the CO₂ of the CO₂ management stream 22 from theunderflow outlet 82 of the hydrocyclone 42. In some embodiments, a heatexchanger, such as described in application Ser. No. 11/855,071, filedSep. 13, 2007, titled Heat Exchanger and Associated Method, owned by theassignee of the present invention, the disclosure thereof previouslyincorporated by reference in its entirely herein, may be utilized as thesublimation chamber 70. In further embodiments, a portion of the gasstream 28, such as an excess flow portion, may be directed through a tee(not shown) and into the mixer 10, rather than being directed into theCO₂ sublimation chamber 70.

The combined gaseous CO₂ from the CO₂ management stream 22 and the gasesfrom the stream 28 may then exit the sublimation chamber 70 as the firsttail gas stream 30, which may be relatively cool. For example, the firsttail gas stream 30 may be just above the CO₂ sublimation temperatureupon exiting the sublimation chamber 70. The first tail gas stream 30may then be directed through a fifth channel of the primary heatexchanger 34 to extract heat from the process stream 12 in the thirdchannel prior to entering the mixer 8 through the first tail gas outlet72 and being directed out of the core module 2 through the primary gasoutlet 8.

Finally, the second tail gas stream 26, which may initially comprise asecondary substantially pure LNG stream from the splitter 46, may bedirected through the pump 78. In additional embodiments, the pump 78 maynot be required and may not be included in the core module 2. Forexample, sufficient pressure may be imparted to the process stream 12within the transfer tank 40 by the transfer motive gas stream 16 suchthat the pump 78 may not be required and may not be included in the coremodule 2. The second tail gas stream 26 may then be directed through asixth channel of the primary heat exchanger 34, where it may extractheat from the process stream 12 in the third channel, and may becomevaporized to form gaseous NG. The second tail stream 26 may then bedirected into the mixer 10 via the second tail gas outlet 80 and out ofthe core module 2 through the primary gas outlet 8.

In some embodiments, as the process stream 12 progresses through theprimary heat exchanger 34, the process stream 12 may be cooled first bythe cooling stream 14, which may extract about two-thirds (⅔) of theheat to be removed from the process stream 12 within the heat exchanger34. Remaining cooling of the process stream 12 within the primary heatexchanger 34 may then be accomplished by the transfer of heat from theprocess stream 12 to the second tail gas stream 26. In view of this, theamount of flow that is directed into the second tail gas stream 26 maybe regulated to achieve a particular amount of heat extraction from theprocess stream 12 within the heat exchanger 34.

In some embodiments, the core module 2 may be configured to utilize adesired site-independent predetermined inlet gas condition, such as adesired site-independent predetermined inlet pressure level and adesired site-independent predetermined inlet temperature level, for thesource gas directed into the primary gas inlet 4. In other words, thecore module 2 may be configured to receive a gas into the primary gasinlet 4 at a pressure and temperature level that may each be selectedindependent of a specific source gas pressure and temperature at a siteat which the core module 2 is to be utilized. Additionally, the coremodule 2 may be configured to utilize a desired site-independentpredetermined outlet gas condition, such as a desired site-independentpredetermined outlet pressure level and a desired site-independentpredetermined outlet temperature level, for the tail gas directed out ofthe primary gas outlet 8.

As the core module 2 may be designed and manufactured independent of aspecific site 88, a modular type natural gas liquefaction plant for aspecific site 88 may include a customized inlet module 90 and acustomized outlet module 92 in addition to the preconfigured core module2, as shown in FIGS. 2 and 3. The inlet module 90 may include an inlet94 to receive a source gas, such as gaseous NG, from the specific site88, such as from a NG supply pipeline 96, into the inlet module 90. Uponentering the inlet module 90 the source gas may be processed, such as byone or more of compression, expansion, cooling, heating, dehydration,and filtration using conventional methods and devices, to meet thesite-independent predetermined inlet gas conditions for the core module2. The source gas may then be directed into the primary gas inlet 4 ofthe core module 2 at the site-independent predetermined inletconditions, such as a site-independent predetermined temperature andpressure.

Additionally, the outlet module 92 may be configured to receive the tailgas stream, including the combined first tail gas stream 30, second tailgas stream 26, and cooling stream 14, directed out of the primary gasoutlet 8 of the core module 2. Upon entering the outlet module 92 thetail gas stream may be processed, such as by one or more of compression,expansion, cooling, and heating using conventional methods and devices,to meet the site 88 specific tail gas requirements. The tail gas maythen be directed out of an outlet 98 of the outlet module 92 to asite-specific location at a site-specific pressure and temperature. Forexample, a site-specific location for the tail gas may be a relativelylow pressure NG pipeline 100, such as shown in FIG. 2, and the tail gasmay be processed to an appropriate relatively low pressure. For anotherexample, the site-specific location for the tail gas may be the same NGsupply pipeline 96 that provides the NG source gas, such as shown inFIG. 3, and the tail gases may require compression within the outletmodule to provide the tail gas to the supply pipeline 96 at anappropriate pressure.

In view of this approach to plant design and configuration, the inletmodule 90 and the outlet module 92 may be configured to enable apreconfigured core module 2 to operate at any number of specific sites,which may each provide a source gas having different properties, such asgas composition, gas pressure, and gas temperature, and may have uniquetail gas requirements. In some cases, one or more of the source gasconditions and the required tail gas conditions for a specific site maycoincidentally meet one or more of the site-independent predeterminedgas conditions for the primary gas inlet 4 and primary gas outlet 8 ofthe core module 2. In such a case, one or more of the inlet module 90and the outlet module 92 may simply be configured as a gas conduit.

The inlet module 90 and the outlet module 92, allow a specific site 88to be adapted to the core module 2, and the core module 2 may beutilized at any number of sites 88 with minimal or no internalmodifications required. In view of the foregoing, a core module 2 may bemass produced and then delivered to numerous sites.

Although a common design between numerous core modules 2 may notnecessarily provide the most energy efficient system at every site, whencompared to custom site-specific plants, a common design for core module2 may result in other efficiencies, improved safety, a reduction inengineering and design cost, a reduction in maintenance cost, improvedreliability and a reduction in initial investment cost that may outweighany inefficiencies that may exist at an individual site.

The core module 2 may be configured with some flexibility in itsmechanical design, such as shown in FIG. 1, to allow accommodation ofsomewhat varying input and output temperatures and pressures withoutnecessitating a replacement of any of the physical components of thecore module 2. However, the plant may be designed and configured forspecific site-independent predetermined gas conditions for the primarygas inlet 4 and the primary gas outlet 5 selected for efficiency.

Provided for example and not limitation, the core module 2 may beconfigured to utilize an inlet pressure level of about 800 psia and ainlet temperature level of about 50° F. to about 120° F. Extensivemodeling has suggested that approximately 800 psia may be the mostefficient incoming pressure. Additionally, for example and notlimitation, the desired predetermined specified outlet pressure level ofthe core module 2 may be about 100 psia. In general, the lower theoutlet pressure level, the higher the production rate. However, fromstudying location data the inventors of the present invention havediscovered that ideal low pressure lines with enough available flow toaccommodate tail gas from the core module 2 are few and may be difficultto access. In view of this, as the designed tail gas outlet pressure ofthe core module 2 is increased, more potential natural gas liquefactionplant sites become available. It is believed at the present time thatselection of a 100 psia outlet pressure may be a good compromise betweenthe relatively few sites with available lower pressure pipelines and themore readily available sites with available higher pressure pipelines.This may also be a good outlet pressure to provide to an outlet module92 having a compressor to increase the gas pressure for a higherpressure pipeline, as it may result in a relatively low compressionratio. Lower compression ratios require less power and may be moreeconomical. Furthermore, an outlet or exit pressure of about 100 psiamay provide efficiencies for the cooling stream 14 of the core module 2,since a higher gas pressure may result in a lower critical temperaturefor certain components of the gas, such as CO₂, which may allow thecooling stream 14 to reach a lower temperature.

While these may be desired pressure levels and temperature levels forthe core module 2, such may vary without substantially impacting theoperation of the core module 2 because the core module 2 describedherein has the flexibility to accommodate such varying conditions ofinlet gas pressure level and temperature level as well as outlet gaspressure level therefrom.

In additional embodiments, the core module 2 may not include the primarygas inlet 4, the splitter 6, the primary gas outlet 8 and the mixer 10.Instead, the inlet gas streams 12, 14, 16 may be maintained separatelyand the outlet gas streams 14, 26, 30 may also be maintained separately,which may provide a more flexible core module 2, such as described inU.S. patent application Ser. No. ______, filed on even date herewith,for METHODS OF NATURAL GAS LIQUEFACTION AND NATURAL GAS LIQUEFACTIONPLANTS UTILIZING MULTIPLE AND VARYING GAS STREAMS (Attorney Docket No.2939-9179US (BA-350)), previously incorporated by reference herein inits entirety.

The core module 2 may have a relatively small physical size and may bereadily transported from one geographic location to another. Such acompact design may allow core modules 2 to be mass produced at one ormore locations and transported to various sites, such as by conventionalrail and roadway transport. Furthermore, the mass production of coremodules 2 may allow components to be purchased and manufactured inrelatively high numbers, which may reduce the cost of components and maymake it economically feasible to design unique and especially efficientcomponents for the core module 2. Mass production may result inreplacement components being relatively inexpensive, resulting in lowermaintenance cost. Furthermore, if a core module 2 at a site becamedamaged and required extensive repair or replacement, the damaged coremodule 2 could be replaced with another substantially identical coremodule 2 that is operable relatively quickly and cost effectively.Additional and various other advantages may also result from the massproduction of substantially identical core modules 2.

Modular LNG plants utilizing substantially identical core modules 2 mayalso be utilized to more efficiently and cost effectively distributeLNG. It may be relatively expensive to ship LNG from a large plant, suchas by truck, to each point-of-use location where it is required. It mayalso be relatively expensive and difficult to provide infrastructure,such as a LNG pipeline, to transport LNG from a large plant to variousdistant locations. However, a plurality of modular LNG plants utilizingsubstantially identical core modules 2 may be located at or near variousLNG point-of-use locations, such as LNG vehicle fueling stations, havingexisting gaseous NG sources, which may have various and differentpressures and temperatures, and produce LNG from the gaseous NG sourcesat or near the LNG point-of-use locations. In view of this, existinggaseous NG infrastructure may be utilized with core modules 2 accordingto the present invention to distribute LNG in a relatively efficient andcost effective manner.

In some embodiments, the core module 2 may be configured as a“small-scale” natural gas liquefaction core module 2 which is coupled toa source of natural gas such as a pipeline 96, although other sources,such as a well head, are contemplated as being equally suitable. Theterm “small-scale” is used to differentiate from a larger-scale planthaving the capacity of producing, for example 70,000 gallons of LNG ormore per day. In comparison, the presently disclosed liquefaction plantmay have a capacity of producing, for example, approximately 30,000gallons of LNG a day but may be scaled for a different output as neededand is not limited to small-scale operations or plants. Additionally,the liquefaction core module 2 of the present invention may beconsiderably smaller in size than a large-scale plant and may betransported from one site to another, as previously described herein.However, the core module 2 may also be configured as a large-scale plantif desired. A core module 2 may also be relatively inexpensive to buildand operate, and may be configured to require little or no operatoroversight.

In further embodiments, a plurality of core modules 2 may be utilized ata single site, such as at sites that have a relatively large LNG demand,sites having variable demand or at critical demand sites. In someembodiments, a site having a relatively high LNG demand may include aplurality of core modules 2, each producing LNG simultaneously to meetthe demand. Provided for example and not limitation, a site having a LNGdemand of about 120,000 gallons a day may utilize four substantiallyidentical core modules 2, each configured to produce about 30,000gallons of LNG a day. Additionally, the site may include one or moreadditional substantially identical core modules 2, which may be rotatedinto use at the site, which may allow individual core modules 2 to beshut down for cleaning, servicing or repairs while backup core modules 2are utilized to make up for the lost LNG production, thus allowing theLNG demand to be met at all times. If a site has a particularly criticalLNG demand, a greater redundancy in core modules 2, and thus backup LNGproduction capacity, may be provided. Additionally, if a site hasvariable demand, as demand increases additional core modules 2 at thesite may be activated and utilized to meet the increased demand,likewise, the additional core modules 2 may be deactivated as demanddecreases.

In additional embodiments, core modules 2 may be designed in severalsizes or capacities, and core modules having different sizes andcapacities may be combined in various combinations to meet anyparticular sites LNG demand.

The core module 2 and methods illustrated and described herein mayinclude the use of any well known apparatus and methods, such as withinthe inlet module 90, to remove carbon dioxide, nitrogen, oxygen, ethane,etc. from the natural gas supply before entry into the core module 2.Additionally, if the source of natural gas has little carbon dioxide,nitrogen, oxygen, ethane, etc., the use of hydrocyclones and carbondioxide sublimation in the liquefaction process and core module 2 maynot be needed and may not be included.

While the invention may be susceptible to various modifications andalternative forms, specific embodiments have been shown by way ofexample in the drawings and have been described in detail herein.However, it should be understood that the invention is not intended tobe limited to the particular forms disclosed. Rather, the inventionincludes all modifications, equivalents, and alternatives falling withinthe scope of the invention as defined by the following appended claims.

1. A method of natural gas liquefaction, the method comprising:liquefying natural gas from a first natural gas source with a first coremodule; and liquefying natural gas from at least a second natural gassource having a gas property different than a gas property of the firstnatural gas source with at least a second core module substantiallyidentical to the first core module.
 2. The method of claim 1, whereinliquefying natural gas from at least a second natural gas source havinga gas property different than a gas property of the first natural gassource comprises liquefying natural gas from at least a second naturalgas source having a gas pressure level different than a gas pressurelevel of the first natural gas source.
 3. The method of claim 1, furthercomprising increasing the gas pressure level of the natural gas from theat least a second natural gas source with an inlet module prior todirecting the natural gas from the at least a second natural gas sourceinto the at least a second core module for liquefaction.
 4. The methodof claim 3, further comprising directing the natural gas from the firstnatural gas source into the first core module and directing the naturalgas from the at least a second natural gas source into the at least asecond core module at substantially the same pressure.
 5. The method ofclaim 4, further comprising directing the natural gas from the firstnatural gas source into the first core module and directing the naturalgas from the at least a second natural gas source into the at least asecond core module at about 800 psia.
 6. The method of claim 1, whereinliquefying natural gas from at least a second natural gas source havinga gas property different than a gas property of the first natural gassource comprises liquefying natural gas from at least a second naturalgas source having a gas temperature different than a gas temperature ofthe first natural gas source.
 7. The method of claim 6, furthercomprising decreasing the gas temperature level of the natural gas fromthe at least a second natural gas source with an inlet module prior todirecting the natural gas from the at least a second natural gas sourceinto the at least a second core module for liquefaction.
 8. The methodof claim 6, further comprising increasing the gas temperature level ofthe natural gas from the at least a second natural gas source with aninlet module prior to directing the natural gas from the at least asecond natural gas source into the at least a second core module forliquefaction.
 9. The method of claim 8, further comprising directing thenatural gas from the first natural gas source into the first core moduleand directing the natural gas from the at least a second natural gassource into the at least a second core module at substantially the sametemperature.
 10. The method of claim 9, further comprising directing thenatural gas from the first natural gas source into the first core moduleand directing the natural gas from the at least a second natural gassource into the at least a second core module at a temperature levelbetween about 50° F. and about 120° F.
 11. The method of claim 1,further comprising: processing a first tail gas expelled from the firstcore module with a first outlet module to change at least one of thepressure level and the temperature level of the first tail gas; andprocessing a second tail gas expelled from the at least a second coremodule with a second outlet module to change at least one of thepressure level and the temperature level of the second tail gas.
 12. Themethod of claim 11, further comprising expelling the first tail from thefirst core module and the second tail gas from the at least a secondcore module at substantially the same temperature and pressure.
 13. Themethod of claim 12, further comprising expelling the first tail from thefirst core module and the second tail gas from the at least a secondcore module at a pressure level of about 100 psia.
 14. The method ofclaim 1, further comprising: expelling a first tail gas comprisingcarbon dioxide out of the first core module; and expelling a second tailgas comprising carbon dioxide out of the at least a second core module.15. A method of designing a natural gas liquefaction plant, the methodcomprising: utilizing a preconfigured core module design for a coremodule configured to receive source gas at site-independentpredetermined input conditions, expel tail gas at site-independentpredetermined outlet conditions, and liquefy natural gas; designing asite-specific inlet module configured to provide source gas from aspecific natural gas source to the core module at the fixedpredetermined input conditions; and designing a site-specific outletmodule configured to convey tail gas from the core module at thepredetermined tail gas outlet conditions to a specific tail gas stream.16. The method of claim 15, wherein designing a site-specific inletmodule configured to provide source gas from a specific natural gassource to the core module at the fixed predetermined input conditionsfurther comprises designing a site-specific inlet module configured toprovide source gas from a specific natural gas source to the core moduleat a pressure level of about 800 psia and at a temperature level ofabout 50° F. and about 120° F.
 17. The method of claim 15, whereindesigning a site-specific outlet module configured to convey tail gasfrom the core module at the predetermined tail gas outlet conditions toa specific tail gas stream further comprises designing a site-specificoutlet module configured to convey tail gas from the core module at apressure level of about 100 psia.
 18. The method of claim 15, whereinutilizing a preconfigured core module design for a core moduleconfigured to liquefy natural gas further comprises utilizing apreconfigured core module design for a core module configured to liquefynatural gas by: cooling a gaseous natural gas process stream bytransferring heat from a gaseous natural gas process stream to a coolingstream; and expanding the cooled gaseous natural gas process stream toform a liquid natural gas process stream.
 19. A method of distributingliquid natural gas, the method comprising: providing a plurality ofnatural gas liquefaction plants comprising substantially identical coremodules to a plurality of gaseous natural gas source locations; andliquefying at least a portion of the gaseous natural gas from each ofthe plurality of gaseous natural gas sources with the plurality ofnatural gas liquefaction plants to provide liquid natural gas at each ofthe plurality of gaseous natural gas source locations.
 20. The method ofclaim 19, wherein providing a plurality of natural gas liquefactionplants comprising substantially identical core modules to a plurality ofgaseous natural gas source locations further comprises providing aplurality of natural gas liquefaction plants comprising substantiallyidentical core modules to a plurality of gaseous natural gas sourcescomprising gaseous natural gas sources having various gas properties.21. The method of claim 19, further comprising locating the plurality ofnatural gas liquefaction plants comprising substantially identical coremodules at a plurality of liquid natural gas point-of-use locations. 22.A modular natural gas liquefaction plant comprising: a core modulecomprising: a processed natural gas inlet configured to receive gaseousnatural gas at a site-independent predetermined pressure andtemperature; a liquid natural gas outlet; and a tail gas outletconfigured to expel a tail gas at a site-independent predeterminedpressure and temperature; an inlet module comprising: a natural gassource inlet configured to receive gaseous natural gas at a temperatureand pressure of a site-specific natural gas source; and a processednatural gas outlet configured to deliver gaseous natural gas to theprocessed natural gas inlet of the core module at the site-independentpredetermined pressure and temperature; and an outlet module comprising:a tail gas inlet configured to receive a tail gas from the tail gasoutlet of the core module at the site-independent predetermined pressureand temperature; and a processed tail gas outlet configured to deliverthe tail gas to a site-specific location at a site-specific pressure andtemperature.
 23. A method of natural gas liquefaction, comprisingliquefying gaseous natural gas with a plurality of substantiallyidentical core modules at a single site.